Control schemes for thermal management of power production systems and methods

ABSTRACT

The present invention relates to systems and methods for controlling a power production plant and optionally providing a one or more product streams for an end use thereof. Control of a power production plant specifically can include executing one or more functions effective for adjusting a heat profile of a heat exchange unit (HEU) operating with a plurality of streams passing therethrough. This can include implementing a control function that alters a flow of one or more of the plurality of streams by adding flow to or withdrawing flow one or more of the plurality of streams at an intermediate temperature range within the HEU at a point that is positioned between a first end and a second end of the HEU.

CROSS REFERENCE TO RELATED APPLICATIONS

The present application claims priority to U.S. Patent App. No.62/924,525, filed Oct. 22, 2019, the disclosure of which is incorporatedherein by reference in its entirety.

FIELD OF THE INVENTION

The present disclosure relates to control systems and methods, and moreparticularly to control systems and methods that can be integrated withpower production systems and methods. The control systems and methodscan be implemented particularly for management of thermal flows into andout of the power production system.

BACKGROUND OF THE INVENTION

There are many known systems and methods for the combustion of fossilfuels to produce electrical power. Although alternative power productionmeans are constantly being pursued, cost factors and availability offossil fuels, especially coals and natural gas (as well as wastehydrocarbons, such as residual oil products), drive a continued need forsystems configured to combust such fuels. Accordingly, there is agrowing need for systems and methods that allow for high efficiencypower production with complete carbon capture.

The ability to provide power production from the burning of fossil fuelswith complete carbon capture provides the potential for large volumeproduction of carbon dioxide as a valuable commodity. The compound isused, for example, in the metals industry (e.g., to enhance hardness incasting molds), in manufacturing and construction (e.g., as a shield gasin MIG/MAG welding), in chemical manufacturing (e.g., as a raw materialin methanol and urea production), in petroleum field management (e.g.,for enhanced oil production techniques), and in the food and beverageindustries (e.g., for carbonation, for use as a refrigerant, forde-caffeinating coffee, for separation and purification of volatileflavor and fragrance concentrates, and for cold sterilization inadmixture with ethylene oxide), to name a few. Depending upon the actualuse, carbon dioxide input to an industrial use often must be pressurizedand/or heated beyond ambient conditions.

Provision of clean CO₂ for uses such as noted above (as well as otheruses) typically includes separation of the CO₂ from an industrial gasmixture, which mixture often contains further compounds, such as CO, H₂,sulfur, and the like. This, of course, requires a series of purificationprocesses. The purification requirements as well as the need forproviding the CO₂ at the desired pressure and/or temperature can entailprocuring dedicated compression, cleanup, and heating equipment thatleads to high capital costs and large energy consumptions.

In addition to the foregoing, power production processes are typicallyconfigured for utilization and production of significant amounts ofthermal energy. This thermal energy may be utilized directly in powerproduction or may be available for further uses. Thus, there is a needfor means for controlling power production processes such that variousproduct flows, such as carbon dioxide and modes of thermal transfer, maybe efficiently obtained and/or exported for a further use.

SUMMARY OF THE INVENTION

In one or more embodiments, the present disclosure can provide systemsand methods useful for controlling one or more aspects of a powerproduction system. The control systems particularly can provide controlover one or more of pressure, temperature, flow rate, and streamcomposition of one or more flow streams in a power production system.The control systems can provide for optimum efficiency of the powerproduction system. The control systems further can provide control overaspects of the power production system, such as start-up of the system,shutdown of the system, change of input stream(s) in the system, changeof output stream(s) in the system, handling of operating emergenciesrelated to the system, and any like considerations related to operationof a power production system. In some embodiments, the control systemscan be particularly adapted to or configured to provide for managementof thermal flows into and out of the power production systems andmethods. For example, thermal flows may be embodied in a heat transferfluid and/or by passage of a dedicated stream in the power productionsystem through a heat exchanger against a dedicated stream in adifferent system.

The present disclosure more particularly can relate to export of CO₂from a power production cycle such that the CO₂ can be utilized in avariety of beneficial end uses without the need for compression and/orheating of the CO₂ at the actual point of use. U.S. Pat. No. 8,596,075to Allam et al., the disclosure of which is incorporated herein byreference, describes a high efficiency power production cycle whereinoxy-fuel combustion is carried out utilizing a recycle CO₂ streamwherein at least a portion of the CO₂ can be captured as a relativelypure stream. Because of the nature of the cycle wherein combustion gasesand recycle CO₂ can be provided at a variety of pressures andtemperatures, such systems and methods can be configured according tothe present disclosure to withdrawn substantially pure CO₂ across abeneficially wide pressure and/or temperature range for export.

In one or more embodiments, the present disclosure thus provides tosystems and methods whereby CO₂ arising from a power production cycleutilizing CO₂ as a working fluid can be taken as an end product and feddirectly into a further downstream use of the material. For example, thesystems and methods of the present disclosure can allow for the exportof CO₂ as a chemical feedstock and/or heat transfer fluid at varioustemperatures and pressures for use in downstream endothermic industrialprocesses.

In some embodiments, the presently disclosed systems and methods arebeneficial in that low-grade heat can be provided to an externalprocess. This may be accomplished in an example embodiment by usingcombustion-derived CO₂ effectively as a heat carrier. Moreover, thepresent disclosure provides for management of plant turndown (i.e.turbine stability and operability) through the export of said low-gradeheat along with changes to the flow rate through the hot gas compressor(“HGC”) of the power production system from which the CO₂ is derived. Assuch, by relying upon the power production cycle utilizing a CO₂ workingfluid can, it is possible to partially or completely eliminate the needfor combustion to be carried out separate from the power productioncycle itself. As such, the maximum temperature can be limited by thetotal heat quality and quantity that can be taken from the recuperativeheat exchanger train utilized in the power production cycle before thehot gas compressor can no longer supplement the losses (i.e. maintainheat exchanger profile). In this manner, the systems and methods of thepresent disclosure can provide distinct advantages over other possibleindustrial sources of CO₂, such as systems wherein CO₂ compression heatis recovered in order to help generate steam that is used to strip CO₂from recovery columns. In such less desirable alternatives, the heatrecovery process is an add-on independent of direct power generationactivities and thus cannot provide many of the advantages of thepresently disclosed systems and methods. As such, known systems andmethods do not include using combustion derived CO₂ taken from asupercritical CO₂ power production cycle, and likewise do notcontemplate supplying external thermal energy for chemical processes byusing CO₂ as a transportable heat sink.

In one or more embodiments, the present disclosure can provide a methodfor providing a CO₂ stream for an end use thereof. For example, suchmethod can comprise: combusting a fuel to form a combustion streamcomprising CO₂; generating power; removing one or more contaminants fromthe combustion stream to provide a substantially pure stream of CO₂; andexporting the substantially pure stream of CO₂ at one or both of atemperature and pressure that is greater than ambient. In particular,exported CO₂ can be at a pressure of about 2 bar or greater, about 5 baror greater, about 10 bar or greater, about 25 bar or greater, about 50bar or greater, or about 100 bar or greater (said export pressure havingan upper limit in line with pressure limits inherent to the equipmentrequired to compress the CO₂ and the equipment used to transport theCO₂). In some embodiment, the pressure can be about 2 bar to about 500bar, about 10 bar to about 490 bar, about 25 bar to about 480 bar, about50 bar to about 475 bar, about 75 bar to about 450 bar, or about 100 barto about 400 bar. Exported CO₂ can be at a temperature of about 35° C.or greater, about 40° C. or greater, about 50° C. or greater, about 75°C. or greater, or about 100° C. or greater (said export temperaturehaving an upper limit in line with temperature limits inherent to theequipment required handling of the CO₂). In some embodiment, thetemperature can be about 35° C. to about 500° C., about 40° C. to about450° C., about 50° C. to about 400° C., or about 60° C. to about 350° C.

In one or more embodiments, the present disclosure can relate to acontrol system suitable for use in a power production plant. Forexample, the power production plant can be a plant burning a fuel insubstantially pure oxygen in a combustor at a pressure of about 12 MPaor greater with an additional circulating CO₂ stream to produce acombined stream of combustion products and circulating CO₂. In someembodiments, the power production can be further characterized by one ormore of the following points, which can be combined in any number ororder.

The combined stream can be passed through a power producing turbine witha discharge pressure of at least 10 bar. The turbine exhaust can becooled in an economizer heat exchange to preheat the circulating CO₂stream. The turbine exhaust can be further cooled to near ambienttemperature, and condensed water can be removed. The CO₂ gas stream canbe compressed to be at or near the turbine inlet pressure using a gascompressor followed by a dense CO₂ pump to form the circulating CO₂stream. Net CO₂ produced in the combustor can be removed at any pressurebetween the turbine inlet and outlet pressures. Heat from an externalsource can be introduced to preheat part of the circulating CO₂ streamto a temperature in the range 200° C. to 400° C. in order to reduce thetemperature difference between the turbine exhaust and the circulatingCO₂ stream leaving the economizer heat exchanger to about 50° C. orless. The fuel flow rate can be controlled to provide the required poweroutput from the turbine. The turbine outlet temperature can becontrolled by the speed of the CO₂ pump. The CO₂ compressor dischargepressure can be controlled by recycling compressed CO₂ flow to thecompressor inlet. The flow rate of net CO₂ produced from fuel gascombustion and removed from the system can be used to control the CO₂compressor inlet pressure. The difference between the temperature of theturbine exhaust entering the economizer heat exchanger and thetemperature of the circulating CO₂ stream leaving the economizer heatexchange can be controlled to be at or below 50° C. by controlling theflow rate of a portion of the circulating CO₂ stream which is heated byan added heat source. The flow rate of net liquid water and fuel derivedimpurities removed from the system can be controlled by the level in theliquid water separator. The oxygen flow rate can be controlled tomaintain a ratio of oxygen to fuel gas flow rate which can result in adefined excess oxygen in the turbine inlet flow to ensure complete fuelgas combustion and oxidation of components in the fuel gas. The oxygenstream at CO₂ compressor inlet pressure can be mixed with a quantity ofCO₂ from the CO₂ compressor inlet to produce an oxidant stream with anoxygen composition of about 15% to about 40% (molar), which can lowerthe adiabatic flame temperature in the combustor. The oxidant flowrequired to produce the required oxygen to fuel gas ratio can becontrolled by the speed of the oxidant pump. The discharge pressure ofthe oxidant compressor can be controlled by recycling compressed oxidantflow to the compressor inlet. The inlet pressure of the oxidantcompressor can be controlled by the flow rate of diluent CO₂ mixed withthe oxygen which forms the oxidant stream. The ratio of oxygen to CO₂ inthe oxidant stream can be controlled by the flow of oxygen. The oxygencan be delivered to the power system at a pressure at least as high asthe turbine inlet pressure and where an oxidant stream with an oxygencomposition in the range of about 15% to about 40% (molar) can bedesired. The oxygen to fuel gas ratio can be controlled by the oxygenflow. The oxygen to CO₂ ratio in the oxidant flow can be controlled bythe flow of diluent CO₂ taken from CO₂ compressor discharge.

In one or more embodiments, the present disclosure can provide powerproduction systems that include an integrated control system, which canbe configured for automated control of at least one component of thepower production system. In particular, the control system can includeat least one controller unit configured to receive an input related to ameasured parameter of the power production system and configured toprovide an output to the at least one component of the power productionsystem subject to the automated control.

The power production system and integrated control system can be furtherdefined in relation to one or more of the following statements, whichcan be combined in any number and order. The integrated control systemcan include a power controller configured to receive an input related topower produced by one or more power producing components of the powerproduction system. The power controller can be configured to meet one orboth of the following requirements: provide an output to a heatercomponent of the power production system to increase or decrease heatproduction by the heater component; provide an output to a fuel valve toallow more fuel or less fuel into the power production system. Theintegrated control system can include a fuel/oxidant ratio controllerconfigured to receive one or both of an input related to fuel flow rateand an input related to oxidant flow rate. The fuel/oxidant ratiocontroller can be configured to meet one or both of the followingrequirements: provide an output to a fuel valve to allow more fuel orless fuel into the power production system; provide an output to anoxidant valve to allow more oxidant or less oxidant into the powerproduction system. The integrated control system can include a pumpcontroller configured to receive an input related to temperature of anexhaust stream of a turbine in the power production system and toprovide an output to a pump upstream from the turbine to increase ordecrease flow rate of a stream exiting the pump. The integrated controlsystem can include a pump suction pressure controller configured toreceive an input related to suction pressure on a fluid upstream from apump in the power production system and to provide an output to aspillback valve that is positioned upstream from the pump. The pumpsuction pressure controller is configured to meet one or both of thefollowing requirements: cause more of the fluid or less of the fluid tospill back to a point that is further upstream from the spillback valve;cause more of the fluid or less of the fluid to be removed from thepower production system upstream from the pump. The integrated controlsystem can include a pressure regulation controller configured toreceive an input related to pressure of an exhaust stream of a turbinein the power production system and to provide an output to a fluidoutlet valve and allow fluid out of the exhaust stream and optionally toprovide an output to a fluid inlet valve and allow fluid into theexhaust stream. The integrated control system can include a waterseparator controller configured to receive an input related to theamount of water in a separator of the power production system and toprovide and output to a water removal valve to allow or disallow removalof water from the separator and maintain the amount of the water in theseparator within a defined value. The integrated control system caninclude an oxidant pump controller configured to receive an inputrelated to one or both of a mass flow of a fuel and a mass flow of anoxidant in the power production system and calculate a mass flow ratioof the fuel and the oxidant. The oxidant pump controller can beconfigured to provide an output to the oxidant pump to change the powerof the pump so as to affect the mass flow ratio of the fuel and theoxidant in the power production system. The integrated control systemcan include an oxidant pressure controller configured to receive aninput related to the pressure of an oxidant stream downstream from anoxidant compressor and to provide an output to an oxidant bypass valveto cause more oxidant or less oxidant to bypass the compressor. Theintegrated control system can include an oxidant pressure controllerconfigured to receive an input related to the pressure of an oxidantstream upstream from an oxidant compressor and to provide an output to arecycle fluid valve to cause more recycle fluid or less recycle fluidfrom the power production system to be added to the oxidant streamupstream from the oxidant compressor. In particular, the recycle fluidcan be a substantially pure CO₂ stream. The integrated control systemcan include a dilution controller configured to receive an input relatedto one or both of the mass flow of an oxidant and the mass flow of anoxidant diluent stream and to calculate a mass flow ratio of the oxidantand the oxidant diluent. The dilution controller can be configured toprovide an output to an oxidant entry valve to allow more oxidant orless oxidant to enter the power production system so that the mass flowratio of the oxidant to the oxidant diluent is within a defined range.The integrated control system can include a compressor suction pressurecontroller configured to receive an input related to suction pressure ofa fluid upstream from a compressor in the power production system and toprovide an output to a spillback valve that is positioned downstreamfrom the compressor and that causes more of the fluid or less fluid tospill back to a point that is upstream from the compressor. Theintegrated control system can include a pump speed controller configuredto receive an input related to suction pressure upstream from the pumpand to provide an output to the pump to increase or decrease pump speed.The integrated control system can include a side flow heat controllerconfigured to receive an input related to a calculated mass flowrequirement for a side flow of a high pressure recycle stream in thepower production system and to provide an output to a side flow valve toincrease or decrease the amount of the high pressure recycle stream inthe side flow.

The power production system can comprise: a turbine; a compressordownstream from the turbine and in fluid connection with the turbine; apump downstream from the compressor and in fluid connection with thecompressor; and a heater positioned downstream from the pump and influid connection with the pump and positioned upstream from the turbineand in fluid connection with the turbine. Optionally, the powerproduction system can include a recuperator heat exchanger.

In one or more embodiments, the present disclosure can provide methodsfor automated control of a power production system. In particular, themethod can comprise operating a power production system comprising aplurality of components that include: a turbine; a compressor downstreamfrom the turbine and in fluid connection with the turbine; a pumpdownstream from the compressor and in fluid connection with thecompressor; and a heater positioned downstream from the pump and influid connection with the pump and positioned upstream from the turbineand in fluid connection with the turbine. Further, operating the powerproduction system can include using one or more controllers integratedwith the power production system to receive an input related to ameasured parameter of the power production system and provide an outputthat automatically controls at least one of the plurality of componentsof the power production system.

In further embodiments, the methods can include one or more of thefollowing steps, which can be combined in any number and order. Theoutput can be based upon a pre-programmed, computerized controlalgorithm. The operating can include using a controller to receive aninput related to power produced by the power production system anddirect one or both of the following actions: provide an output to theheater to increase or decrease heat production by the heater; provide anoutput to a fuel valve of the power production system to allow more fuelor less fuel into the power production system. The operating can includeusing a controller to receive one or both of an input related to fuelflow rate and an input related to oxidant flow rate and to direct one orboth of the following actions: provide an output to a fuel valve of thepower production system to allow more fuel or less fuel into the powerproduction system; provide an output to an oxidant valve of the powerproduction system to allow more oxidant or less oxidant into the powerproduction system. The method operating can include using a controllerto receive an input related to temperature of an exhaust stream of theturbine and provide an output to the pump upstream from the turbine toincrease or decrease flow rate of a stream exiting the pump. Theoperating can include using a controller to receive an input related tosuction pressure on a fluid upstream from the pump and provide an outputto a spillback valve that is positioned upstream from the pump. Inparticular, one or both of the following requirements can be met: thecontroller causes more of the fluid or less of the fluid to spill backto a point that is further upstream from the spillback valve; thecontroller causes more of the fluid or less of the fluid to be removedfrom the power production system upstream from the pump. The operatingcan include using a controller to receive an input related to pressureof an exhaust stream of the turbine and provide an output to a fluidoutlet valve and allow fluid out of the exhaust stream and optionallyprovide an output to a fluid inlet valve and allow fluid into theexhaust stream. The operating can include using a controller to receivean input related to the amount of water in a separator included in thepower production system and provide and output to a water removal valveto allow or disallow removal of water from the separator and maintainthe amount of the water in the separator within a defined value. Theoperating can include using a controller to receive an input related toone or both of a mass flow of a fuel and a mass flow of an oxidantintroduced to the power production system and calculate a mass flowratio of the fuel and the oxidant. In particular, the controller canprovide an output to an oxidant pump to change the power of the pump soas to affect the mass flow ratio of the fuel and the oxidant in thepower production system. The operating can include using a controller toreceive an input related to the pressure of an oxidant stream downstreamfrom an oxidant compressor and provide an output to an oxidant bypassvalve to cause more oxidant or less oxidant to bypass the compressor.The operating can include using a controller to receive an input relatedto the pressure of an oxidant stream upstream from an oxidant compressorand to provide an output to a recycle fluid valve to cause more recyclefluid or less recycle fluid to be added to the oxidant stream upstreamfrom the oxidant compressor. In particular, the recycle fluid can be asubstantially pure CO₂ stream. The operating can include using acontroller to receive an input related to one or both of the mass flowof an oxidant and the mass flow of an oxidant diluent stream and tocalculate a mass flow ratio of the oxidant and the oxidant diluent. Inparticular, the controller can be configured to provide an output to anoxidant entry valve to allow more oxidant or less oxidant to enter thepower production system so that the mass flow ratio of the oxidant tothe oxidant diluent is within a defined range. The operating can includeusing a controller to receive an input related to suction pressure of afluid upstream from the compressor and provide an output to a spillbackvalve that is positioned downstream from the compressor and that causesmore of the fluid or less fluid to spill back to a point that isupstream from the compressor. The operating can include using acontroller to receive an input related to suction pressure upstream fromthe pump and to provide an output to the pump to increase or decreasepump speed. The operating can include using a controller to receive aninput related to a calculated mass flow requirement for a side flow of ahigh pressure recycle stream and provide an output to a side flow valveto increase or decrease the amount of the high pressure recycle streamin the side flow.

In some embodiments, methods for control of a power production plant cancomprise: adjusting a heat profile of a heat exchange unit (HEU)operating with a plurality of streams passing between a first HEU endhaving a first operational temperature and a second HEU end having asecond, lower operational temperature; wherein said adjusting comprisesimplementing a control function that alters a mass flow of one or moreof the plurality of streams passing between the first HEU end and thesecond HEU end by adding mass flow to or withdrawing mass flow from theone or more of the plurality of streams at an intermediate temperaturerange within the HEU at a point that is positioned between the first HEUend and the second HEU end. Such methods may be further defined inrelation to one or more of the following statements, which can becombined in any number and order.

The adjusting can comprise causing a portion of a heated stream passingthrough the HEU to bypass a section of the HEU through a bypass linesuch that said adjusting is effective to reduce the mass flow of theheated stream that passes through the section of the HEU that isbypassed.

The heated stream passing through the HEU can be a heated turbineexhaust stream from a turbine, the heated turbine exhaust stream passingfrom the first HEU end to the second HEU end to provide a cooled turbineexhaust stream, and wherein the cooled turbine exhaust stream can befurther processed through one or more of a separator, a compressor, anda pump.

The control function can comprise causing the portion of the heatedstream passing through the HEU to bypass the section of the HEU throughthe bypass line responsive to one or both of the following signalsreceived by a controller: a signal indicating a change in power demandeffective to cause an operational change of the turbine altering powergeneration from the power production plant; and a signal indicating thata temperature within the HEU is within a defined threshold of a maximumoperating temperature of the HEU.

The control function can comprise opening a valve positioned in thebypass line.

The portion of the heated stream passing through the bypass line can berejoined with the cooled turbine exhaust stream downstream from thesecond HEU end and upstream from one or more of the separator, thecompressor, and the pump.

The method further can comprise causing the portion of the heated streampassing through bypass line to be processed through a bypass heatexchanger effective to transfer heat from the portion of the heatedstream in the bypass line to one or more further streams.

The adjusting can comprise one or both of the following: causing aportion of a recycle stream being heated in the HEU to be passed to anexhaust stream being cooled in the HEU such that said adjusting iseffective to increase the mass flow of the exhaust stream passingthrough a section of the HEU; and causing a portion of an oxidant streambeing heated in the HEU to be passed to an exhaust stream being cooledin the HEU such that said adjusting is effective to increase the massflow of the exhaust stream passing through a section of the HEU.

The control function can comprise causing the respective portion of therecycle stream and the oxidant stream to be passed to the exhaust streamresponsive to one or both of the following: a signal indicating a changein power demand effective to cause an operational change of a turbinealtering power generation from the power production plant; a signalindicating that a temperature within the HEU is within a definedthreshold of a maximum operating temperature of the HEU.

The power production plant can include a recirculation compressorconfigured for withdrawing a portion of a heated turbine exhaust streampassing through the HEU, compressing the portion of the heated turbineexhaust stream that is withdrawn, and recombining the portion of theheater turbine exhaust stream that is compressed at a downstream sectionof the HEU.

The control function can comprise closing an inlet guide vane (IGV) ofthe recirculation compressor responsive to a signal indicating that atemperature within the HEU is within a defined threshold of a maximumoperating temperature of the HEU.

The method further can comprise adding heat to one or more of theplurality of streams passing between the first HEU end and the secondHEU end, wherein the heat is added at an intermediate temperature rangewithin the HEU at a point that is positioned between the first HEU endand the second HEU end, and wherein the heat is added using a heaterthat is operated independent of the HEU.

The heater can be a combustion heater.

The heat can be added to a turbine exhaust stream passing through theHEU, and wherein an exhaust stream from the combustion heater is addeddirectly to the turbine exhaust stream.

In further embodiments, the present disclosure may particularly relateto power production plants. For example, a power production plant cancomprise: a turbine; a power generator; a heat exchange unit (HEU); oneor more compressors or pumps; and a control unit; wherein the HEU isconfigured for heat exchange between a plurality of streams passingbetween a first HEU end having a first operational temperature and asecond HEU end having a second, lower operational temperature; whereinthe HEU includes one or more components configured to add mass flow toor withdraw mass flow from one or more of the plurality of streams at apoint that is positioned between the first HEU end and the second HEUend such that a portion of a fluid passing through the one or more ofthe plurality of streams is diverted from passage through a remainingsection of the HEU; and wherein the control unit is configured toreceive a signal defining an operating condition of the power productionplant and, based thereon, output a signal effective to control the oneor more components configured to add mass flow to or withdraw mass flowfrom the one or more of the plurality of streams. Such power plants maybe further defined in relation to one or more of the followingstatements, which can be combined in any number and order.

The HEU can be configured for heat exchange between at least a turbineexhaust stream exiting a turbine and one or both of a recycle stream andan oxidant stream.

The one or more components configured to add mass flow to or withdrawmass flow from one or more of the plurality of streams can include abypass line and a bypass valve configured to divert a portion of theturbine exhaust stream around a section of the HEU.

The power production plant further can comprise a bypass heat exchangeroperational with the bypass line and configured to transfer heat fromthe portion of the turbine exhaust stream diverted therethrough to oneor more further streams.

The one or more components configured to add mass flow to or withdrawmass flow from one or more of the plurality of streams can include arecirculation line and a recirculation valve interposed between theturbine exhaust stream and the recycle stream.

The one or more components configured to add mass flow to or withdrawmass flow from one or more of the plurality of streams can include arecirculation line and a recirculation valve interposed between theturbine exhaust stream and the oxidant stream.

The power production plant further can comprise a heater that isconfigured for operation independent of the HEU, the heater beingconfigured for addition of heat to the turbine exhaust stream at a pointthat is positioned between the first HEU end and the second HEU end.

The heater can be a combustion heater.

In further embodiments, the present disclosure can provide systems forcogeneration of power and one or more end products. Such systems cancomprise: a power production unit including at least a combustor, aturbine, a heat exchanger, and a separation unit, the power productionunit being configured to receive a fuel stream and an oxidant and outputpower and substantially pure carbon dioxide; a syngas production unitconfigured to receive a feedstock and provide a syngas product, at leasta portion of which is effective for use as at least a portion of thefuel stream in the power production unit; an air separation unitconfigured to provide oxygen for use as the oxidant in the powerproduction unit and configured to provide nitrogen; and one or both ofan ammonia synthesis unit and a urea synthesis unit. In furtherembodiments, such systems may be defined in relation to one or more ofthe following statements, which can be combined in any number and order.

The ammonia synthesis unit can be present and can be configured toreceive nitrogen from the air separation unit, configured to receivehydrogen from a hydrogen source, and configured to output ammonia.

The hydrogen source can be a hydrogen separation unit configured toreceive at least a portion of the syngas product from the syngasproduction unit and provide a stream of hydrogen and a stream ofhydrogen-reduced syngas that is effective for use as at least a portionof the fuel stream in the power production unit.

The urea synthesis unit can be present and can be configured to receivenitrogen from a nitrogen source, configured to receive carbon dioxidefrom the power production cycle, and configured to output a urea stream.

The nitrogen source can be the ammonia synthesis unit.

BRIEF DESCRIPTION OF THE FIGURES

FIG. 1 is a diagram of a power production system and method according toan example embodiment of the present disclosure.

FIG. 2 is a diagram of a power production system and method according toanother example embodiment of the present disclosure.

FIG. 3 is a diagram of a power production system and method according toa further example embodiment of the present disclosure.

FIG. 4 is a diagram of a power production system and method according toan additional example embodiment of the present disclosure.

FIG. 5 is a diagram of a power production system and method according toyet another example embodiment of the present disclosure.

FIG. 6 is a flowchart showing a process whereby power can be produced inconnection with formation of one or more products suitable for exportaccording to example embodiments of the present disclosure.

DETAILED DESCRIPTION

Various aspects of the present disclosure will now be described morefully hereinafter with reference to the accompanying drawings, in whichsome, but not all implementations of the disclosure are shown. Indeed,various implementations of the disclosure may be expressed in manydifferent forms and should not be construed as limited to theimplementations set forth herein; rather, these exemplaryimplementations are provided so that this disclosure will be thoroughand complete, and will fully convey the scope of the disclosure to thoseskilled in the art. As used in the specification, and in the appendedclaims, the singular forms “a”, “an”, “the”, include plural referentsunless the context clearly dictates otherwise.

In one or more embodiments, the present disclosure provides systems andmethods for control of power production. The control systems and methodscan be utilized in relation to a wide variety of power productionsystems. For example, the control systems and methods may be utilized inpower production system and methods utilizing a turbine for expansion ofa pressurized fluid, particularly wherein turbine outlet temperature isheld substantially constant or within a narrowly defined temperaturerange (e.g., 20° C., 15° C., 10° C., or 5° C.). In some embodiments, thepresent systems and methods may be defined in that the mechanism thatcontrols turbine inlet pressure may be substantially decoupled from theturbine itself. In example embodiments, this can be in the form of acompressor or pump downstream of a primary pressurization machine thatcan either be shafted to the turbine or not. In other exampleembodiments, the turbine may be connected to a generator and a singleindependently driven pressurization device can work in consort with theworking fluid. In such embodiments, the control point between thecompressor and pump may be substantially eliminated as described herein.

Examples of power production systems and methods wherein a controlsystem as described herein can be implemented are disclosed in U.S. Pat.No. 9,068,743 to Palmer et al., U.S. Pat. No. 9,062,608 to Allam et al.,U.S. Pat. No. 8,986,002 to Palmer et al., U.S. Pat. No. 8,959,887 toAllam et al., U.S. Pat. No. 8,869,889 to Palmer et al., U.S. Pat. No.8,776,532 to Allam et al., and U.S. Pat. No. 8,596,075 to Allam et al,the disclosures of which are incorporated herein by reference. As anon-limiting example, a power production system with which a controlsystem as presently described may be utilized can be configured forcombusting a fuel with O₂ in the presence of a CO₂ circulating fluid ina combustor, preferably wherein the CO₂ is introduced at a pressure ofat least about 12 MPa and a temperature of at least about 400° C., toprovide a combustion product stream comprising CO₂, preferably whereinthe combustion product stream has a temperature of at least about 800°C. Such power production system further can be characterized by one ormore of the following, which may be combined in any number and/or order:

the combustion product stream can be expanded across a turbine with adischarge pressure of about 1 MPa or greater to generate power andprovide a turbine discharge steam comprising CO₂;

the turbine discharge stream can be passed through a heat exchanger unitto provide a cooled discharge stream;

the cooled turbine discharge stream can be processed to remove one ormore secondary components other than CO₂ to provide a purified dischargestream;

the purified discharge stream can be compressed to provide asupercritical CO₂ circulating fluid stream;

the supercritical CO₂ circulating fluid stream can be cooled to providea high density CO₂ circulating fluid (preferably wherein the density isat least about 200 kg/m3);

the high density CO₂ circulating fluid can be pumped to a pressuresuitable for input to the combustor;

the pressurized CO₂ circulating fluid can be heated by passing throughthe heat exchanger unit using heat recuperated from the turbinedischarge stream;

all or a portion of the pressurized CO₂ circulating fluid can be furtherheated with heat that is not withdrawn from the turbine discharge stream(preferably wherein the further heating is provided one or more of priorto, during, or after passing through the heat exchanger); and/or

the heated pressurized CO₂ circulating fluid can be recycled into thecombustor (preferably wherein the temperature of the heated, pressurizedCO₂ circulating fluid entering the combustor is less than thetemperature of the turbine discharge stream by no more than about 50°C.).

The presently disclosed control systems can be particularly useful inrelation to power production methods such as exemplified above becauseof the need for providing precise control over multiple parameters inrelation to multiple streams, such parameters needing precise control toprovide desired performance and safety. For example, in one or moreembodiments, the present control systems can be useful in relation toany one or more of the functions otherwise described herein. In someembodiments, a control system and method as described herein inparticular may include any one or more elements and/or features asdescribed in U.S. Pat. No. 10,103,737 to Fetvedt et al., the disclosureof which is incorporated herein by reference.

In one or more embodiments, the presently disclosed systems and methodscan relate to heat profile regulation such as in relation to the systemsillustrated in FIG. 1 through FIG. 5. Such systems generally can includeat least one control unit 100 configured to receive one or more controlinputs 101 effective to signal to the control unit 100 to execute one ormore control functions implemented via one or more control outputs 102.Control inputs 101 may relate to a measurable property, such astemperature, pressure, flow rate, power output, and the like, and thepresently described systems may include one or more sensors or othermeasurement components configured to provide the desired output. Thecontrol outputs 102 may be effective to cause a change in operation ofthe system, such as opening or closing one or more valves, changing acompression pressure or pump speed to modify a flow rate of one or morestreams, or similar operational variables. To this end, useful controlsystems can be adapted to or configured to control power output and/orturbine exhaust temperature in various power cycle configurations. Whilemaintaining a substantially constant turbine outlet temperature at heatexchanger 50 can reduce stress related to thermal cycling, it does notcompletely eliminate it. The present disclosure thus can provideadditional control functions to address such shortcomings. For example,as power demand at turbine 10 is reduced, a corresponding reduction inoutput pressure and mass flow can occur at pump 20. This can lead to achange in the heat exchanger thermal profile.

In example embodiments, the present disclosure can provide one or morecontrol functions effective to maintain system efficiency regardless offluctuating power demand on the system and, alternatively oradditionally, to prevent the temperature within one or more sections ofthe heat exchange unit from exceeding a defined threshold temperature(which can be related to a maximum operating temperature). For instance,a primary recuperative heat exchanger that has been designed andoptimized for conditions compatible with full power output at theturbine can increasingly over-perform as power demand decreases. This isbecause the heat exchanger surface area will have been specified forrelatively larger mass flow rates at the turbine exhaust and highpressure working fluid (such as supercritical carbon dioxide) recyclestreams. This likewise may apply to oxidant flow as well. The reductionin pressure at the high-pressure working fluid recycle side can alsolead to a lower specific heat of the recycle fluid (oxidant flow too ifincluded). These changes may cumulatively manifest as increasing averageheat exchanger temperature. To at least partially address such concerns,in some embodiments, the heat exchanger 50 may be configured as aplurality of heat exchangers in series, and the interface temperaturesbetween the units can rise as power demand at the turbine decreases.Such swings in temperature can create thermal stress, but moreimportantly, they may also lead to failure modes.

In some embodiments it can be desirable to construct heat exchanger 50to be as cost-effective as possible. Such an approach can lead to theuse of differing materials throughout the range of temperatures in theheat exchanger 50. While all materials preferably are rated to themaximum outlet pressure of pump 20 at full turbine power output (minimallosses for best performance), it will be necessary to design thematerials to different temperatures as a means of promoting lowest costsolutions (cheapest materials and lowest cumulative masses).Accordingly, it can be preferable for the plant controls to include oneor more functions effective for influencing the intermediatetemperatures of heat exchanger 50 in order to prevent design limitexcursions given changes in heat exchanger average temperature that mayoccur. This may be achieved in a variety of manners as discussed herein.More particularly, the control functions may be effective to prevent oneor more sections of a heat exchange unit (HEU) from exceeding a maximumoperating temperature. As such, one or more controls may be implement tooutput a signal indicating that a temperature within the HEU (or withinone or more specific sections of an HEU) is within a defined thresholdof a maximum operating temperature. Such threshold may be, for exampleless than 20% below, less than 10% below, or less than 5% below themaximum operating temperature as defined by the manufacturer.Specifically, the threshold for outputting a high temperature signal maybe a range that is within 20% to 1%, within 15% to 1%, within 10% to 1%,within 20% to 2%, within 15% to 2%, within 15% to 5%, within 10% to 2%,or within 10% to 5% of the maximum operating temperature.

The present disclosure therefore can relate to methods for control of apower production plant. In particular, FIGS. 1-5 illustrate schematicflow diagrams of a power production plant according to variousembodiments, and the present methods may be implemented to incorporateany combination of elements and/or functions described in relation tosaid figures and/or expressly illustrated in said figures. In someembodiments, a control method may comprise adjusting a heat profile of aheat exchange unit (HEU) 50 operating with a plurality of streamspassing between a first HEU end 50′ having a first operationaltemperature and a second HEU end 50″ having a second, lower operationaltemperature. More particularly, the step of adjusting may includeimplementing a control function that alters a mass flow or volume flowof one or more of the plurality of streams passing between the first HEUend 50′ and the second HEU end 50″ by adding fluid (e.g., mass flow orvolume flow) to or withdrawing fluid from (e.g., mass flow or volumeflow) the one or more of the plurality of streams. This addition orwithdrawal of fluid to the one or more streams may be carried out at anintermediate temperature range within the HEU. This means that theaddition or withdrawal specifically can be carried out at a point thatis positioned between the first HEU end 50′ and the second HEU end 50″.In other words, this can occur upstream from the second HEU end anddownstream from the first HEU end. This can be, for example, atapproximately a midpoint of the HEU 50 or at a point that is within5-45%, 10-40%, or 20-35% of the distance from the first HEU end or at apoint that is within 5-45%, 10-40%, or 20-35% of the distance from thefirst HEU end. Thus, the addition or withdrawal of fluid may take placeat a section of the HEU that is nearer the first end (i.e., the “hot”end) or at a section of the HEU that is nearer the second end (i.e., the“cold” end). Any of these positions may be referenced herein as an“intermediate” position in the HEU. In some embodiments, the HEU may bea single integrated unit. In other embodiments, the HEU may becombination of a plurality of HEU sections that are fluidly connected.Thus, an intermediate position in the HEU may be a position between twodiscrete HEU sections.

In one or more embodiments, as illustrated in FIG. 1, one or moreturbine exhaust bypass lines may be utilized for protection of the heatexchanger 50. Generally, in FIG. 1, fuel passes in line 13 from a fuelsource 12, optionally being compressed in a fuel compressor 14, to becombusted in combustor 15. Oxidant pass through line 22 from oxidantsource 25, which may, for example, and air separation unit, oxygenmembrane, or other oxidant source. The oxidant may be passed directly tothe combustor 15 but, as illustrated, the oxidant can be mixed withrecycled CO₂ in mixer/union 27 before being compressed in pump 40 andpassed in line 29 through the heat exchanger 50 on route to thecombustor 15. In the combustor, the fuel is combusted with the oxidantin the presence of recycled CO₂ to form an exhaust stream in line 16that is then expanded in turbine 10 to generate power (e.g.,electricity) in a generator 17. Turbine exhaust then leaves the turbine10 in line 18.

To effect bypass as noted previously, the turbine exhaust stream in line18 is passed through the heat exchanger 50, and a portion of the turbineexhaust stream exits the heat exchanger 50 in line 1 at an intermediatetemperature. As illustrated in FIG. 1, the heat exchanger 50 is shown astwo separate heat exchange sections 50 a and 50 b; however, the dashedlines illustrate that the separate heat exchange sections may beconnected as a single HEU operating with a plurality of sections (e.g.,2 or more, 3 or more, or even more portions) at different conditions.Valve 5 can be opened by the controller as needed so that a portion offlow of the turbine exhaust stream may leave the HEU to later rejoin themain turbine exhaust flow at a point upstream of heat exchanger 70and/or upstream from the separator 35, and/or upstream from thecompressor 30, and/or upstream from the pump 20. Thus, the heat profileof the HEU can be effectively adjusted by causing a portion of theturbine exhaust stream (i.e., a heated stream) to bypass a section ofthe HEU through a bypass line. Removing a portion of the turbine exhaustgas from line 18 at an intermediate point from heat exchanger 50 has thenet effect of reducing the total thermal energy transferred below thetemperature in the heat exchanger at which the turbine exhaust stream inline 1 is taken. This results in a reduced average temperature for theremaining portion of the heat exchanger (e.g., available heat in heatexchange section 50 b) at the expense of increasing the rejected duty atheat exchanger 70.

If desired, the heat in the turbine exhaust stream removed throughbypass line 1 may also be used to heat fluids other than the recycledCO₂ that is provided through line 39 and the oxidant that is providedthrough line 29 to heat exchanger 50. To this end, bypass heat exchanger60 can use the bypass stream in line 1 as a heat source to providethermal energy to any process outside of the illustrated power cycle. Itshould be noted that bypass heat exchanger 60 may simply be a dedicatedsection of the heat exchanger network 50 (e.g., bypass heat exchanger 60may be integral to heat exchanger 50 and operated so that only thestream in line 1 passes therethrough for heat removal).

The control function implemented in this fashion thus can cause aportion of a heated stream passing through the HEU to bypass a sectionof the HEU through the bypass line 1 response to one or more signalsreceived by the controller 100. For example, the input signal receivedby the controller 100 can be a signal indicating that a temperaturewithin the HEU is within a defined threshold of a maximum operatingtemperature of the HEU. For example, a temperature output 101 can begenerated from one or more temperature sensors at one or more checkpoints within the HEU. Temperature check points within heat exchanger 50can be configured to provide feedback to a controller operating valve 5.As such, the controller 100 may output a signal 102 a to the valve 4 orto a further component of the power production plant to case more orless fluid to pass through the bypass line 1 as appropriate for thegiven conditions. As intermediate temperatures within heat exchanger 50approach maximum design limits, the controller providing control overvalve 5 will send a signal to valve 5 to open. This will encourage theflow of the stream in line 1 through the bypass heat exchanger 60 beforepassing on to heat exchanger 70. If operating conditions (e.g., powerdemand) are such that the intermediate temperatures in heat exchanger 50are below design limits, then valve 5 may remain closed (or be closed ifpreviously opened) in order to bias the flow through the remainder ofheat exchanger 50 (e.g., heat exchange section 50 b). This has thebenefit of improving the thermal recovery of the power cycle. Any numberof bypasses may be integrated in parallel into heat exchanger 50 as ameans of providing more finite temperature control at various parts ofthe exchanger train. The controller for valve 5 and/or any othertemperature control valves may in fact operate in such a manner that thepower cycle is operated sub-optimally whereby heat recovery within thepower cycle is minimized. This scenario may occur when the use of carbonfree thermal energy is of greater use at heat exchanger 60 than for theproduction of power at turbine 10.

In further embodiments, control of the bypass line 1 may be effectedbased upon power output from the turbine 10 and the generator 17. Forexample, a signal 101 b indicating a change in power demand effective tocause an operational change of the turbine 10 altering power generationfrom the generator 17 of the power production plant can be received bythe controller 100. In response, the controller 100 can provide anoutput 102 b that causes more or less fluid to pass through line 1.

The power production cycle otherwise may continue in that the turbineexhaust in line 18 can merge with the bypass stream in line 1, such asin a mixer/union 21, prior to passage in line 19 to heat exchanger 70,wherein the exhaust stream is cooled to near ambient temperature. Theexhaust stream then passes through 34 to separator 35 wherein asubstantially pure stream of CO₂ is provided in line 36. The stream ofCO₂ is then compressed in compressor 30, optionally cooled in heatexchanger 80, then pumped in pump 20 to the desired pressure range to berecycled back to the combustor 15 through line 39. Optionally, a portionof the CO₂ stream in line 39 can be branched in line 38 and passed tothe mixer/union 27, as referenced above, for admixture with the oxidant.Likewise, a portion of the CO₂ in line 39 may be separated and passedthrough line 37 for export or other end use, such as EOR. Water fromseparator 35 can be passed out of the system through drain line 33.

An additional means of heat exchanger temperature control may alsoincorporate one or more control functions in addition to the abovementioned bypass scheme. FIG. 2 thus illustrates a further exampleembodiment, wherein elements already described in relation to FIG. 1 aresubstantially unchanged. In FIG. 2, the power production system can beconfigured to provide for recirculation of at least a portion of one orboth of the flows passing through the heat exchanger 50 from pump 20 andpump 40. For example, valve 6 can be utilized for recirculation of atleast a portion of recycle CO₂ stream passing through the heat exchanger50 in line 39 so that said portion of the recycle CO₂ stream is passedto the turbine exhaust stream in line 18. Likewise, valve 7 can beutilized for recirculation of at least a portion of the oxidant streampassing through the heat exchanger 50 in line 29 so that said portion ofthe oxidant stream is passed to the turbine exhaust stream in line 18.

Adjusting a heat profile of the HEU thus can include one or both of thefollowing: causing a portion of a recycle stream being heated in the HEUto be passed to an exhaust stream being cooled in the HEU such that saidadjusting is effective to increase the mass flow of the exhaust streampassing through a section of the HEU; and causing a portion of anoxidant stream being heated in the HEU to be passed to an exhaust streambeing cooled in the HEU such that said adjusting is effective toincrease the mass flow of the exhaust stream passing through a sectionof the HEU. More particularly, as the desired output of turbine 10 isincreased, the discharge flow rates of pump 20 and/or pump 40 to thecombustor 15 can be controlled to likewise increase as needed. Shouldthe pumps be operating as fixed speed units, the appropriate valve inthe respective recirculation line (e.g., valve 6 in line 39 a or valve 7in line 29 a) in the heat exchanger 50 will begin to close. This willnot only deliver more mass flow to the combustor 15 (and ultimately tothe turbine 10), but it will also increase the amount of thermal energyprovided by the heat exchanger 50 to the combustor 15. Otherwise, when apower output of the turbine 15 is reduced, valve 6 and valve 7 can beopened as needed. This artificially increases the flow rate through thelower half of the heat exchanger 50 (e.g., through heat exchange section50 b) and quenches the turbine exhaust temperature to further helpmanage the heat exchanger temperature profile.

The control function therefore can comprise causing one or both of aportion of the recycle stream and a portion of the oxidant stream to bepassed to the exhaust stream responsive to one or both of the followinginputs: a signal indicating a change in power demand effective to causean operational change of a turbine altering power generation from thepower production plant (see signal 101 b in FIG. 1); and a signalindicating that a temperature within the HEU is within a definedthreshold of a maximum operating temperature of the HEU (see signal 101a in FIG. 1). Output signals 102 c and 102 d may thus be generated forcontrolling fluid passage through valve 6 and valve 7, respectively.Although signals 101 a and 101 b are shown as example embodiments, it isunderstood that similar signals may be received from a variety ofcomponents of the present systems. For example, input signals may bereceived by the controller from any of the pump 20, the pump 40, thecompressor 30, the compressor 31, an IGV 32, the separator 35, thecompressor 14, and any of the lines described herein. As such, signalsmay relate information directed to a pressure at a certain point in thesystem, a flow rate at a certain point in the system, a temperature at acertain point in the system, a molar concentration of a compound at acertain point in the system, or any similar parameter that may be usefulfor implementing a control function as otherwise described herein. Forexample, suitable input signals may include any one or more of thefollowing: a power demand signal; a gasifier output signal (e.g.,indicating that the syngas flow exceeds a defined threshold amount); ahydrogen demand signal (e.g., indicating that the hydrogen flow exceedsa defined threshold amount); a syngas chemistry signal from the gasifier(e.g., which can be indicative that the estimated or actual molefraction of one or more components of the produced syngas exceeds adefined threshold); a signal defining a syngas chemistry for the syngasstream being sent to the power cycle (the mixed stream from the bypassand the reduced hydrogen syngas stream); a feedstock modificationsignal; an ASU operation signal; a nitrogen availability signal; a mixedfuel Wobbe index signal; and the like. Likewise, output signals may bedirected for control of any one or more of the above-exemplifiedcomponents of the system in order to implement a control function asotherwise described herein.

In embodiments wherein it may be desirable to operate the turbine 10 soas to have a maximum output (e.g., operating at full load), then theheat exchanger bypass line 1 may be used to limit the rate oftemperature change in the heat exchanger 50 in conjunction with themaximum flow rates of pump 20 and/or pump 40 being provided nearinstantaneously through the heat exchanger 50 with minimal use of therecirculation lines (29 a, 39 a).

In one or more embodiments, a power cycle according to the presentdisclosure can be operated to utilize one or more recompression systems,and such systems likewise can be controlled so as to manage the flowthrough the recompression cycle to achieve intermediate temperaturemanagement in the heat exchanger 50. Recompression systems not onlypressurize the recycle fluid but also provide low-grade heat to thepower cycle's main recuperative heat exchanger (e.g., heat exchanger 50)as a means of recycle temperature optimization. FIG. 3 depicts adirectly fired sCO2 cycle with a recompression system originating fromwithin the heat exchanger 50. The recirculation compressor 31 thus canbe configured for withdrawing a portion of a heated turbine exhauststream passing through the HEU 50, compressing the portion of the heatedturbine exhaust stream that is withdrawn, and recombining the portion ofthe heater turbine exhaust stream that is compressed at a downstreamsection of the HEU. As illustrated, the portion of the turbine exhauststream is withdrawn between HEU section 50 a and HEU section 50 b and isrecombined in HEU section 50 b.

As described above, a reduction in power demand from such a system willgenerate a higher average heat exchanger temperature. This impactscompressor 31 in recompression line 3 by increasing its suctiontemperature (and thereby also its outlet temperature) as a constantoutlet pressure is maintained. Energy consumption of compressor 31 willalso be expected to increase in such embodiments. In some embodiments,this trend may be effectively reversed by actively reducing the flowrate through compressor 31 while maintaining a substantially constantoutlet temperature for the exhaust stream in line 3. A controller forcompressor 31 can actively monitor one or more check points on line 3 toensure that the stream in line 3 does not exceed an optimized desiredtemperature by providing feedback to location of the inlet guide vane(IGV) 32 of the compressor 31. In this fashion, the control function cancomprise closing an inlet guide vane (IGV) 32 of the recirculationcompressor 31 responsive to a signal indicating that a temperaturewithin the HEU is within a defined threshold of a maximum operatingtemperature of the HEU (see, for example, signal 101 a in FIG. 1). Suchoutput signal is shown in FIG. 3 as signal 102 e.

Under traditional control, the IGVs are used to limit power consumptionwhile maintaining a safe margin to surge. IGVs may be used to controldischarge pressure through various controllers. However, in certainsituations, the IGVs may be placed into manual control and forced openin order to increase the flow in the recycle lines. In such a case, theinventory of the system will increase. This may be done in order topre-empt a change in load or turning on the downstream pump. In morespecific relation to temperature optimization as presently disclosed, asthe optimized temperature is approached, the IGVs of the compressor 31can be closed in order to decrease exhaust flow through the unit. Thereduction in flow and subsequent low-grade heat addition to the heatexchanger 50 can create a cascading effect where average heat exchangertemperature will reduce. Eventually the feedback of reducing flow andreducing suction temperature at the compressor 31 will converge upon amode of operation where the requirement at the check point is satisfied.This will also lead to the lowest energy consumption at compressor 31required to maximize the recycle temperature level that may be obtainedwith the heat exchanger 50. When the IGVs of compressor 31 close, theIGVs of compressor 30 may need to open to allow it to pressurize anincreased amount of flow. Alternatively, should heat recuperation occurat heat exchanger 60, then the suction temperature of compressor 31 mayfall and so may the temperature check point on line 3. This wouldactually force the IGVs of compressor 31 to open to generate more heat.Opposing, the IGVs of compressor 30 would need to close to account forincreased flow at compressor 31. In all scenarios, IGVs may besubstituted with recirculation lines and coolers.

In further embodiments, another manner of providing heat to the heatexchanger network 50 can be carried out as illustrated in FIG. 4. Inparticular, a further heat source (heater 90) can be provided at anintermediate temperature in the heat exchanger 50. The heater 90 mayoperate by providing heat directly or indirectly. The source of heat canalso vary such as it may come from electricity, solar, nuclear, or fuelcombustion resources. The heater 90 may also be located on any of thestreams within the heat exchanger network 50. In one embodiment, heater90 is an oxy-fired duct burner on the exhaust flow of turbine 10.Combusted fuel emissions freely mix with the turbine exhaust flow andcontribute to a temperature rise. This addition of thermal energy mayserve several purposes. For example, as illustrated, heater 90 islocated downstream of the bypass line 1, the recirculation lines 29 aand 39 a, and the recompression line 3, which are all described above.In this situation, the plant may be essentially preheated while thebalance of the cycle around turbine 10 operates in a substantiallyclosed-loop manner. The bypass lines associated with valve 6 and/orvalve 7 may divert part or all of their source flows. The design flowrates can be configured to accommodate over-speed protection of theturbine 10 in the event of a trip scenario. In further embodiments, theheater 90 may be used to provide additional thermal energy for heatexchanger 60 to the extent that the temperature profile of the heatexchanger network 50 is minimally affected. In such embodiments, line 1may be reconfigured to branch from the turbine exhaust flow line 18downstream of the heater 90 within the heat exchanger network 50. In yetanother embodiment, heat provided from the heater 90 can be used tostimulate the closure of the IGVs at compressor 31. Without a poweroutput change at turbine 10 or change in the heat exchanger profile ofthe heat exchanger 50, the net power out of the plant will be expectedto increase due to pressurization of the recycle working fluidpreferentially being diverted to compressor 30, which is typicallyconfigured to have relatively greater operational efficiency.

In addition to the turbine exhaust temperature impacting the profile ofthe heat exchanger 50, the temperatures of the streams entering the heatexchanger 50 through lines 29 and/or 39 likewise will affect the heatexchanger profile since it serves as the low temperature energy sink. Inembodiments wherein the heat exchanger 50 is being optimized for a fullpower output, there is an assumed temperature that the recycle fluid hasas it leaves pump 20 and enters the heat exchanger 50. When the cycleexperiences a reduction in power output, the temperature of the recyclefluid entering heat exchanger 50 will drop given the reduction in workrequired at pump 20 for a lower pressure. This has the impact ofdecreasing the average heat exchanger temperature. While such an effectmay not promote exceeding the design limits of the intermediatetemperature check points of heat exchanger 50, it does increase thermalcycling as turbine power output is varied. This phenomenon can be abatedby increasing the work done at pump 20 in order to maintain nearconstant outlet temperature. A temperature check point on the recycleCO₂ stream in line 39 at the outlet of pump 20 can be used to providefeedback to a controller working in association with pump 20. Thecontroller can be used to bias the set point pressure at the outlet ofcompressor 30. If load demand at the turbine is to decrease or thecooling temperature at heat exchanger 80 is to decrease, then the setpoint pressure at compressor 30 would reduce as well (with the inverseoperations likewise occurring). While it is desirable to maintain nearconstant outlet temperature at pump 20, this may not be feasible in allscenarios. The suction pressure of pump 20 preferably is not permittedto drop below a temperature-pressure correlation curve related to theworking fluid. The curve depicts coincident temperatures and pressuresrequired at heat exchanger 80 that result in a single phase workingfluid that meets a minimum specific gravity compatible for use in pump20. Should a further reduction in compressor 30 outlet pressure not befeasible, then the cooling duty at heat exchanger 80 can be reduceduntil the desired set point temperature at the outlet of pump 20 isachieved. The variation in cooling duty can promote an iterativebalancing of cooling duty and compressor 30 outlet pressure until theminimum requirements of the temperature-pressure correlation curve aremet. It should be noted that the aforementioned scheme is compatiblewith any number of compressors and pumps in series. Moreover, changes incooling water temperature can provide a comparable effect as loadchanges and can be treated in a similar manner.

In addition to the temperature control schemes above, the temperature ofthe heat exchanger 50 may also be adjusted when pump 20 and/or pump 40are off. This can be achieved, for example, through the modulation ofcooling water through cooler 80 and/or cooler 70 or intercoolers withincompressor 30 (e.g., when compressor 80 is configured as a multi-stagecompressor with intercooling). It may be desirable to provide excess lowgrade heat into the cold end of heat exchanger 50 in order to providethe same temperature regulation as described above. Furthermore, thetemperature regulation of said heat exchangers can also be used toinfluence the inlet temperatures of the downstream pump 20 and/or pump40 to the extent that the work they provide generates dischargeconditions capable of also providing main recuperative heat exchangerwork. This can be done as an alternative to reducing inlet pressurewhich feasibly can generate comparable conditions. The inlet pressure ofthe various pumps may be maintained at a constant pressure, meanwhilethe temperature can be adjusted to provide the appropriate outlettemperature needed to balance the heat exchangers given thecorresponding outlet pressure.

The various temperature control schemes described herein can be usedindependently or in any combination with one or more of the furthercontrol schemes described herein. Should multiple temperature controlschemes be used simultaneously, their activities can be prioritized in amanner as described herein. In particular, it can be preferred that theflow rate through the turbine exhaust bypass through line 1 is minimizedin all levels of turbine power output. This is because the thermalenergy contained in the flow moving through the bypass line 1 can bederived from the heat source driving the power cycle. Preserving amaximum amount of heat transfer between the turbine exhaust and recyclefluid facilitates the highest power cycle efficiency. Alternatively, theuse of heater 90 can negate this effect and allow heat recovery at heatexchanger 60 to merely share balance of plant resources with the powercycle. Thereafter, the outlet temperature of pump 20 can be controlledto its optimal value. Lastly, the flow rate through the recompressionsystem (e.g., line 3 and compressor 31) can be minimized or maximized tothe extent that the temperature at check point on line 3 approaches itsoptimal desired value.

In further embodiments, heat management may be provided via one or morecontrol functions related to the power cycle turbine arrangement. As canbe seen in FIG. 5, multiple turbines or turbine sections operating inseries may be configured to have one or more intervening heat sources inaddition to the primary combustor 15. In FIG. 5, two turbines 10 a and10 b are illustrated with one intervening heat source 90, but two ormore, three or more, or even further turbines or turbine sections may beused along with one or more, two or more, ore even more intervening heatsources. Specifically, as illustrated, the combustor exhaust in line 16passes to the first turbine 10 a to power generator 17 a and provide afirst turbine exhaust in line 18 a, which is passed through interveningheater 90. The heated stream leaving the intervening heater 90 in line18 b passes to the second turbine (or last turbine) 10 b to powergenerator 17 b and provide a second turbine (or last turbine) exhaust inline 18 c, which passes on to the heat exchanger 50, as otherwisedescribed herein.

The heat provided in intervening heater 90 may be derived from anysource (e.g., steam, solar, combustion). In certain embodiments, asshown in FIG. 5, the heater 90 may be a combustion heater. Thus, fuelfrom fuel source 12 may be provided to the heater 90 through line 130,and oxidant from the oxidant source 25 may be provided to the heater 90through line 220.

As with the primary control logic described herein, flow control at thepump 20 can be used to control the inlet temperature to the heatexchanger 50 during substantially steady-state and transient conditions.Changes in load output at the turbine array (e.g., leaving any turbinepresent in the array or, more specifically, leaving the last turbine inthe array) may be achieved by diverting more or less flow from thecombustor 10 to the intervening heater 90. The valve 8 present in line37 can be used to maintain a constant outlet pressure from the turbine10 b, and movement of fuel between the combustor 15 and the interveningheater 90 can change the resulting inlet temperatures of the respectiveunits and therefore also change the pressures of the streams enteringturbine 10 a and turbine 10 b. Subsequently the relative work donerespectively by turbine 10 a and turbine 10 b can also change for agiven system fuel input. The exact conditions of operation for turbine10 a and turbine 10 b can have a material impact on the efficiency ofthe units. In such a system configuration, a fixed fuel flow may lead tovarious permutations of net power output due to the changing of theexpanders' operational characteristics given their inherent performancecurves. Associated with this effect will also be that the overall systemflowrate provided by pump 20 may be varied in accordance withmaintaining a constant temperature into the heat exchanger 50. Whilefuel flow to the power cycle may be held constant, when a reduction inpower output is desired, the exhaust flow rate through heat exchanger 50may be artificially manipulated in order to continue heat scavenging atheater 60.

As is evident from FIG. 1 through FIG. 5, the present disclosure canrelate not only to methods for controlling power production plants butalso to configurations of power plants themselves. A power productionplant may include any combination of the components described inrelation to the noted figures or as otherwise described herein. Forexample, a power production plant can comprise at least a turbine 10, apower generator 17, a heat exchange unit (HEU) 50, one or morecompressors 30 or pumps 20, and a control unit 100. In addition, the HEU50 particularly can be configured for heat exchange between a pluralityof streams passing between a first HEU end 50′ having a firstoperational temperature and a second HEU end 50″ having a second, loweroperational temperature. The streams can include, for example, a turbineexhaust stream 18, a recycle stream 39 (which can comprise substantiallypure carbon dioxide), and an oxidant stream 29 (which can comprisesubstantially pure oxygen, can comprise air, or can comprise a mixtureof oxygen and carbon dioxide).

In addition, the HEU can include one or more components configured toadd mass flow to or withdraw mass flow from one or more of the pluralityof streams at a point that is positioned between the first HEU end 50′and the second HEU end 50″ such that a portion of a fluid passingthrough the one or more of the plurality of streams is diverted frompassage through a remaining section of the HEU. For example, referencingFIG. 1, a portion of the turbine exhaust stream 18 is diverted throughbypass line 1 and thus is diverted from passage through HEU section 50b. Further to the above, the control unit can be configured to receive asignal 101 defining an operating condition of the power production plantand, based thereon, output a signal 102 effective to control the one ormore components configured to add flow to or withdraw flow from (e.g.,mass flow or volume flow) one or more of the plurality of streams. Insome embodiments, the HEU 50 can be configured for heat exchange betweenat least a turbine exhaust stream exiting a turbine and one or both of arecycle stream and an oxidant stream. Further, the one or morecomponents configured to add flow to or withdraw flow from one or moreof the plurality of streams can include a bypass line 1 and a bypassvalve 5 configured to divert a portion of the turbine exhaust streamaround a section of the HEU. In such configurations, the plant can alsoinclude a bypass heat exchanger 60 operational with the bypass line 1and configured to transfer heat from the portion of the turbine exhauststream diverted therethrough to one or more further streams 2.

In some embodiments, the one or more components configured to add flowto or withdraw flow from one or more of the plurality of streams caninclude a recirculation line 39 a and a recirculation valve 6 interposedbetween the turbine exhaust stream 18 and the recycle stream 39.Similarly, the one or more components configured to add flow to orwithdraw flow from one or more of the plurality of streams can include arecirculation line 29 a and a recirculation valve 7 interposed betweenthe turbine exhaust stream 18 and the oxidant stream 29.

In further embodiments, the power production plant can include a heater90 that is configured for operation independent of the HEU 50. Suchindependent operation can mean simply that the heat provided by theheater 90 is from a source other than any heated stream that is used toprovide heat exchange in the HEU 50. For example, the heater 90 can beconfigured for addition of heat to the turbine exhaust stream 18 at apoint that is positioned between the first HEU end 50′ and the secondHEU end 50″. As noted already above, the heater 90, for example, can bea combustion heater. Further configurations and components can beidentified based upon the further components that are illustrated inrelation to FIG. 1 through FIG. 5 as already discussed above.

In some embodiments, a power cycle control as described herein by becombined with a liquefied natural gas (LNG) regasification terminal. Seefor example, U.S. Pat. No. 9,523,312 to Allam et al., the disclosure ofwhich is incorporated herein by reference. In such embodiments. A fuelflow rate and its associated blower for temperature modulation may bemodulated to adjust for regasification demand in addition to powerdemand.

In some embodiments, the present systems and methods may be adapted toor configured to adjust for happenings wherein a turbine may leakthrough its seals. In such a case, a compressor may be added in order torecompress the seal leakage and place it back into the cycle between thestream and compressor. In such cases, the same compressor may also beused for startup to fill the system from an external tank or pipeline.In such a case, the compressor discharge may be controlled with acontroller to regulate the low pressure of the system. The suction ofthe compressor may be controlled to cause either positive or negativepressure at the turbine gland seals. The change from positive tonegative pressure may change throughout operation in order to adjust thechemistry from atmospheric contamination.

During steady-state operation of a combustion cycle such as noted above,combustion derived products must be continuously removed from the cycle(e.g., removal of CO₂ through line 37 and/or water removal through line33) in order to maintain a mass balance with the incoming fuel andoxidant. The resulting H₂O and CO₂ must be drained and/or vented;however, if the vapor phase CO₂ is to be used in a downstream process,it may be discharged at a pressure up to that of the turbine inletpressure. First it needs to undergo a de-watering step. Any residualSOx/NOx can be removed in situ (e.g., in separator 35). The CO₂ can thenbe compressed and/or pumped to the desired pressure using the workingfluid turbo-machinery present in the power production cycle.Additionally, the CO₂ stream may be subjected to a cleanup processwhereby minor contaminants such as O₂ and Ar are further removed. Atthis point the stream can be exported for the downstream use.

If it is necessary for the CO₂ to be at an elevated temperature prior touse in the downstream process, it may be desirable to heat it againstthe main recuperative heat exchanger train in the power production cyclecounter-currently to the turbine exhaust flow path. As the export flowis heated up against the heat exchanger array, the recycle CO₂ enteringthe turbine will drop in temperature. In order to prevent this change,the flow rate through the hot gas compressor can be increased by openingthe inlet guide vanes (“IGVs”) on the unit. This will serve the purposeof providing an increase in low-grade heat to the heat exchanger train.It will also reduce the total flow rate of CO₂ through the main CO₂compressor. This will force the IGVs on this unit to close in order toaccommodate the new conditions. The total gross power output at theturbine will not change given that the inlet conditions will remain thesame as beforehand. There also won't be a change in fuel input to thefacility given that the recycle CO₂ temperature has been maintained.Rather, the net power output of the plant will reduce given that the hotgas compressor operates less efficiently as a pressurization device thanthe main CO₂ compressor. The basic effect is that fuel has beenconverted to electricity to then be exported as thermal energy in thedischarged CO₂ stream. All combustion and pressurization activities areinherently managed by the equipment and controls capabilities of thepower cycle. The quality and quantity of heat to the downstream processmay be varied by the amount of export CO₂ heated by the recuperativeheat exchanger train as well as the total flow rate of CO₂ processed bythe hot gas compressor.

In some embodiments, the presently disclosed systems and methods allowthe hot gas compressor in the power production cycle to provide lowgrade heat for the optimization of the recuperative heat exchanger whilealso serving as a heat source for external industrial processesutilizing the cycle's export CO₂ as a feedstock and/or heat transferfluid. The hot gas compressor is managed in such a way that the inletconditions to the turbine (and therefore gross performance) do notchange while heat is being provided to a downstream industrial process.Therefore, thermal cycling of the turbine does not occur. The net poweroutput of the power production cycle, however, is reduced given that theheat generated for the external industrial process increases theparasitic load of the hot gas compressor (i.e., effectively convertingelectricity back into thermal energy). This has the impact of varyingthe CO₂ generated per MWhr produced for the power production cycle(allows for flexibility in addressing disparities in CO₂ demand versuspower demand). The benefit to a downstream industrial process is thatthe need for dedicated heat generation (e.g., natural gas burners, etc.)and heat recovery equipment (steam boilers, tube and shell exchangers,feed water pumps, etc.) is eliminated. As well, the downstream processis able to operate without an emissions profile since the generation ofthermal energy via combustion has occurred at the turbine of the powerproduction cycle. In addition, different from other chemical processes,CO₂ generated in power production cycle is purified by its combustionand downstream DeSNOx processes without any additional equipment andsolvents. Any residual gaseous fuel, such as CH₄, CO, H₂C₂H₆, is removedfrom CO₂ by combustion, and any steam, NOx, and/or SOx are removed at adownstream direct contact cooler

The control functions available according to the present disclosure canenable the currently described power production systems and methods tobe utilized for producing a variety of end products in addition toenergy. The CO₂ generation, compression, and heating processes can becompletely contained within the power production cycle, and it is thuspossible to take advantage of equipment that is already necessary forthe power cycle even if the downstream industrial process did not exist.The combustion of natural gas for thermal input into a downstreamprocess may take advantage of off peak power pricing. This may enablethe power production cycle to function as a tri-generation plantproviding power, CO₂, and heat.

In some embodiments, urea synthesis may be particularly combined withthe power cycle, and this can require an ammonia source. The necessaryammonia (NH₃) can be either a co-product of the underlying powerproduction cycle, or it can be bought as a commodity (e.g., from outsideammonia plants). In embodiments wherein NH₃ is purchased as a commodity,a power production cycle according to the present disclosure exportingCO₂ for urea synthesis can be carried out to provide a method forco-production of power and urea. Specifically, CO₂ can be formed in thecombustion process as otherwise described herein (e.g., taken as aproduct from line 37, taken at an increased temperature from some pointin line 39, or taken at a lower pressure upstream from the pump 20).Beneficially, high grade heat of combustion can be recuperated from thecombustor exhaust or a turbine exhaust stream (e.g., at a point from theheat exchanger 50) by counter-current heating of cold, recycle CO₂ tothe required combustion inlet temperature. This can be specifically thepressurized stream exiting the pump 20. The IGV 32 of the compressor(e.g., compressor 31) can be opened to increase the CO₂ flow rate at theinlet of the compressor, thus increasing the low grade heat (e.g., atapproximately a temperature of 150 to 300° C.) generated from thecompressor for the downstream Urea synthesis process. The flow rate ofCO₂ at the compressor inlet can be dictated by the amount of extra lowgrade heat required for downstream Urea synthesis. Meanwhile, the IGV ofthe main compressor 30 can be closed to adjust CO₂ entering itcorrespondently. Total CO₂ at the primary heat exchanger 50 outlet canbe sent to the separator 35 for liquid water removal, and SOx/NOx (ifany) removal. CO₂ can be compressed and pumped to the required pressure(e.g., in compressor 30 and pump 20), and a portion of the CO₂ can beseparated from the main CO₂ stream at a pressure of about 140-175 bar.The separated CO₂ can be directed into the primary heat exchanger 50 tobe heated to about 190° C., then this portion of CO₂ at about 140-175bar and about 190° C. can be sent to the downstream Urea productionunit. The final temperature, pressure, and flow rate of this portion ofthe CO₂ can be dictated by the Urea synthesis process. Low grade heatthat may be needed can be generated from the compressor 31 or similarunit. Any remaining, required CO₂ can be pumped to combustion inletpressure, heated to combustion inlet temperature against the turbineexhaust stream in the primary heat exchanger 50, and directed into thecombustor 15. The primary heat exchanger profile is maintained by thisapproach.

In further embodiments, a power production cycle according to thepresent disclosure exporting CO₂ for urea synthesis can be carried oututilizing ammonia that is co-generated in the power production cycle. Insuch embodiments, a suitable feedstock can be processed in a suitablesyngas production unit (e.g., via being sent to a gasifier or a steammethane reforming (“SMR”) unit to create raw syngas. The raw syngas canbe processed through a suitable separation unit (e.g., a membraneseparation unit) wherein hydrogen can be separated from raw syngas forAmmonia synthesis. Hydrogen lean syngas can be sent to the combustor andturbine of the power production cycle for power generation as otherwisedescribed herein, and the hydrogen (or a portion thereof) can be sent toan ammonia synthesis unit. Turbine exhaust (CO₂ stream) can be directedinto the primary heat exchanger for high grade heat recuperation. Aportion of the CO₂ can be directed into the compressor for low gradeheat generation for Urea synthesis. The total CO₂ stream exiting theheat exchanger can then be directed to a DeSNOx unit for SOx/NOxremoval. In this unit, which can be used as a replacement for, or inaddition to, the separator 35, all the sulfur compounds in the feedstockare removed from the CO₂ stream. Therefore, an acid gas removal systemor flue gas desulfurization system is eliminated for thispoly-generation system. The CO₂ exiting the DeSNOx unit is at ambienttemperature and about 30 bar, and it is free of liquid water andSOx/NOx. Nitrogen from an air separation unit (which can be an integralpart of the power production cycle) and hydrogen from the membraneseparator are sent to an ammonia synthesis unit. The operating conditionof ammonia synthesis can be at a pressure of about 200-250 bar and atemperature of about 400 to 500° C. The heat source of the ammoniasynthesis process can be derived from the turbine exhaust, hot gascompression, or other heat source in the system. Ammonia produced fromthe ammonia synthesis unit can be sold as a chemical product, or can besent to a Urea synthesis unit along with clean CO₂ from DeSNOx processfor producing Urea. Production of one or both of ammonia and urea can beas illustrated in FIG. 6.

In further embodiments, the power cycle as described herein can becombined with processes such as retorting of kerogen. Kerogen iscurrently retorted by collecting open mine material and placing it intoa furnace. Processes according to the present disclosure can entirelyavoid mining and can provide options for harvesting and use of deepreserves that are currently unusable. In an example embodiment,pressurized and heated (e.g., heating to a temperature of about 50-150°C. for oil production or to a temperature of about 150-200° C. for gasproduction) CO₂ can be injected into a kerogen reserve below gradecontaining bitumen. The heated CO₂ migrates through the sedimentary rockstructure forming the bitumen resulting in the formation of lighterhydrocarbons either in the form of oil and/or gas. The pressure of theCO₂ forces the lighter hydrocarbons to the surface for collection.

In yet further embodiments, the power cycle can be utilized in relationto carbon capture, utilization, and storage in a saline aquifer. Forexample, pressurized CO₂ (e.g., from line 37) can be delivered to asaline storage site at the required reservoir pressure. Prior to beinginjected below grade, the stream can be preheated to a temperature abovethe reservoir's water dew point through the systems and methodsdescribed herein utilizing a power production cycle. Upon contacting thesaline aquifer, a portion of the liquid content is vaporized. A mixtureof steam (desalinated water) and a portion of the injected CO₂ flowthrough an adjacent relief well allowing for the harvest of water andreuse of CO₂ at the surface. In addition to performing desalination, thereservoir has been depressurized allowing for further CO₂ storage.

In some embodiments as described herein, a stream of CO₂ can be treatedfor oxygen removal to improve the ability to utilize the CO₂ inhydrocarbon recovery. In example embodiments, the IGVs of one or morehot gas compressors can be opened such that an increase in flow isprovided to heat a stream of CO₂ equivalent to the plant export flow upto a temperature of about 250° C. (which temperature can be greater insome embodiments depending upon the compressor design). The plant exportflow can be provided at a desired pressure through the main heatexchanger 50 and heated against the compressor flow or can be directlyderived from the compressor at its discharge. The heated CO₂ exportstream then can be supplied to a mixer where methane, natural gas, or H₂is introduced. The heated mixed stream then can be processed through acatalytic combustor where the heat energy catalyzes oxidation of thefuel content with the residual O₂ content in the CO₂. The resultingstream includes substantially no O₂ and contains and increased residualfuel content, CO₂ content, and/or H₂O content. The stream then can becooled and have all or part of the water content removed.

As can be seen from the foregoing, the present disclosure particularlycan provide systems and methods for cogeneration of power and one ormore end products. In an example embodiment, with reference specificallyto FIG. 6, the system can comprise: a power production unit including atleast a combustor, a turbine, a heat exchanger, and a separation unit,the power production unit being configured to receive a fuel stream andan oxidant and output power and substantially pure carbon dioxide; asyngas production unit configured to receive a feedstock and provide asyngas product, at least a portion of which is effective for use as atleast a portion of the fuel stream in the power production unit; an airseparation unit configured to provide oxygen for use as the oxidant inthe power production unit and configured to provide nitrogen; and one orboth of an ammonia synthesis unit and a urea synthesis unit.

In certain embodiments, the ammonia synthesis unit specifically can bepresent. In such cases, it can be desirable for the ammonia synthesisunit to be configured to receive nitrogen from the air separation unit,configured to receive hydrogen from a hydrogen source, and configured tooutput ammonia. In related embodiments, the hydrogen source can be ahydrogen separation unit configured to receive at least a portion of thesyngas product from the syngas production unit and provide a stream ofhydrogen and a stream of hydrogen-reduced syngas that is effective foruse as at least a portion of the fuel stream in the power productionunit.

In some embodiments, the urea synthesis unit specifically can bepresent. In such cases, it can be desirable for the urea synthesis unitto be configured to receive nitrogen from a nitrogen source, configuredto receive carbon dioxide from the power production cycle, andconfigured to output a urea stream. In related embodiments, the nitrogensource specifically can be the ammonia synthesis unit.

As further seen in FIG. 6, the systems and methods can incorporate theuse of an optional bypass and control which can allow a portion of thesyngas to bypass the hydrogen separation and proceed directly to thepower cycle. This allows for more freedom of operation and a partialde-coupling of the gasifier, the power cycle, and the hydrogenproduction. In one or more embodiments, the bypass line may becontrolled based upon a variety of input signals that may be received bythe controller (e.g., controller 100 in FIGS. 1-5). For example,suitable input signals may include any one or more of the following: apower demand signal; a gasifier output signal (e.g., indicating that thesyngas flow exceeds a defined threshold amount); a hydrogen demandsignal (e.g., indicating that the hydrogen flow exceeds a definedthreshold amount); a syngas chemistry signal from the gasifier (e.g.,which can be indicative that the estimated or actual mole fraction ofone or more components of the produced syngas exceeds a definedthreshold); a signal defining a syngas chemistry for the syngas streambeing sent to the power cycle (the mixed stream from the bypass and thereduced hydrogen syngas stream); a feedstock modification signal; an ASUoperation signal; a nitrogen availability signal; a mixed fuel Wobbeindex signal; and the like. Based upon one or more these input signals,one or more of the operational units defined in FIG. 6 may beoperationally adjusted to provide the desired end product and/or thedesired power output. Likewise, such signals may be utilized to modifyprocess efficiency for any one or more of the individual units (e.g.,power production, syngas production, hydrogen production, ammoniaproduction, air product production, and urea production). Likewise, suchsignals can be utilized to adjust a total economic output of thefacility.

Many modifications and other embodiments of the invention will come tomind to one skilled in the art to which this invention pertains havingthe benefit of the teachings presented in the foregoing descriptions andassociated drawings. Therefore, it is to be understood that theinvention is not to be limited to the specific embodiments disclosed andthat modifications and other embodiments are intended to be includedwithin the scope of the appended claims. Although specific terms areemployed herein, they are used in a generic and descriptive sense onlyand not for purposes of limitation. Use of the words “about” and“substantially” herein can indicate relative degrees such that a valuethat is “about” a certain value or “substantially” a certain value canspecifically be the exact amount +/−5%, +/−4%, +/−3%, +/−2%, or +/−1%.

1. A method for control of a power production plant, the methodcomprising: adjusting a heat profile of a heat exchange unit (HEU)operating with a plurality of streams passing between a first HEU endhaving a first operational temperature and a second HEU end having asecond, lower operational temperature; wherein said adjusting comprisesimplementing a control function that alters a mass flow of one or moreof the plurality of streams passing between the first HEU end and thesecond HEU end by adding mass flow to or withdrawing mass flow from theone or more of the plurality of streams at an intermediate temperaturerange within the HEU at a point that is positioned between the first HEUend and the second HEU end.
 2. The method of claim 1, wherein saidadjusting comprises causing a portion of a heated stream passing throughthe HEU to bypass a section of the HEU through a bypass line such thatsaid adjusting is effective to reduce the mass flow of the heated streamthat passes through the section of the HEU that is bypassed.
 3. Themethod of claim 2, wherein the heated stream passing through the HEU isa heated turbine exhaust stream from a turbine, the heated turbineexhaust stream passing from the first HEU end to the second HEU end toprovide a cooled turbine exhaust stream, and wherein the cooled turbineexhaust stream is further processed through one or more of a separator,a compressor, and a pump.
 4. The method of claim 3, wherein the controlfunction comprises causing the portion of the heated stream passingthrough the HEU to bypass the section of the HEU through the bypass lineresponsive to one or both of the following signals received by acontroller: a signal indicating a change in power demand effective tocause an operational change of the turbine altering power generationfrom the power production plant; a signal indicating that a temperaturewithin the HEU is within a defined threshold of a maximum operatingtemperature of the HEU.
 5. The method of claim 4, wherein the controlfunction comprises opening a valve positioned in the bypass line.
 6. Themethod of claim 4, wherein the portion of the heated stream passingthrough the bypass line is rejoined with the cooled turbine exhauststream downstream from the second HEU end and upstream from one or moreof the separator, the compressor, and the pump.
 7. The method of claim2, further comprising causing the portion of the heated stream passingthrough bypass line to be processed through a bypass heat exchangereffective to transfer heat from the portion of the heated stream in thebypass line to one or more further streams.
 8. The method of claim 1,wherein said adjusting comprises one or both of the following: causing aportion of a recycle stream being heated in the HEU to be passed to anexhaust stream being cooled in the HEU such that said adjusting iseffective to increase the mass flow of the exhaust stream passingthrough a section of the HEU; causing a portion of an oxidant streambeing heated in the HEU to be passed to an exhaust stream being cooledin the HEU such that said adjusting is effective to increase the massflow of the exhaust stream passing through a section of the HEU.
 9. Themethod of claim 8, wherein the control function comprises causing therespective portion of the recycle stream and the oxidant stream to bepassed to the exhaust stream responsive to one or both of the following:a signal indicating a change in power demand effective to cause anoperational change of a turbine altering power generation from the powerproduction plant; a signal indicating that a temperature within the HEUis within a defined threshold of a maximum operating temperature of theHEU.
 10. The method of claim 1, wherein the power production plantincludes a recirculation compressor configured for withdrawing a portionof a heated turbine exhaust stream passing through the HEU, compressingthe portion of the heated turbine exhaust stream that is withdrawn, andrecombining the portion of the heater turbine exhaust stream that iscompressed at a downstream section of the HEU.
 11. The method of claim1, wherein the control function comprises closing an inlet guide vane(IGV) of the recirculation compressor responsive to a signal indicatingthat a temperature within the HEU is within a defined threshold of amaximum operating temperature of the HEU.
 12. The method of claim 1,further comprising adding heat to one or more of the plurality ofstreams passing between the first HEU end and the second HEU end,wherein the heat is added at an intermediate temperature range withinthe HEU at a point that is positioned between the first HEU end and thesecond HEU end, and wherein the heat is added using a heater that isoperated independent of the HEU.
 13. The method of claim 12, wherein theheater is a combustion heater.
 14. The method of claim 13, wherein theheat is added to a turbine exhaust stream passing through the HEU, andwherein an exhaust stream from the combustion heater is added directlyto the turbine exhaust stream.
 15. A power production plant comprising:a turbine; a power generator; a heat exchange unit (HEU); one or morecompressors or pumps; and a control unit; wherein the HEU is configuredfor heat exchange between a plurality of streams passing between a firstHEU end having a first operational temperature and a second HEU endhaving a second, lower operational temperature; wherein the HEU includesone or more components configured to add mass flow to or withdraw massflow from one or more of the plurality of streams at a point that ispositioned between the first HEU end and the second HEU end such that aportion of a fluid passing through the one or more of the plurality ofstreams is diverted from passage through a remaining section of the HEU;and wherein the control unit is configured to receive a signal definingan operating condition of the power production plant and, based thereon,output a signal effective to control the one or more componentsconfigured to add mass flow to or withdraw mass flow from the one ormore of the plurality of streams.
 16. The power production plant ofclaim 15, wherein the HEU is configured for heat exchange between atleast a turbine exhaust stream exiting a turbine and one or both of arecycle stream and an oxidant stream.
 17. The power production plant ofclaim 16, wherein the one or more components configured to add mass flowto or withdraw mass flow from one or more of the plurality of streamsincludes a bypass line and a bypass valve configured to divert a portionof the turbine exhaust stream around a section of the HEU.
 18. The powerproduction plant of claim 17, further comprising a bypass heat exchangeroperational with the bypass line and configured to transfer heat fromthe portion of the turbine exhaust stream diverted therethrough to oneor more further streams.
 19. The power production plant of claim 16,wherein the one or more components configured to add mass flow to orwithdraw mass flow from one or more of the plurality of streams includesa recirculation line and a recirculation valve interposed between theturbine exhaust stream and the recycle stream.
 20. The power productionplant of claim 16, wherein the one or more components configured to addmass flow to or withdraw mass flow from one or more of the plurality ofstreams includes a recirculation line and a recirculation valveinterposed between the turbine exhaust stream and the oxidant stream.21. The power production plant of claim 16, further comprising a heaterthat is configured for operation independent of the HEU, the heaterbeing configured for addition of heat to the turbine exhaust stream at apoint that is positioned between the first HEU end and the second HEUend.
 22. The power production plant of claim 21, wherein the heater is acombustion heater.
 23. A system for cogeneration of power and one ormore end products, the system comprising: a power production unitincluding at least a combustor, a turbine, a heat exchanger, and aseparation unit, the power production unit being configured to receive afuel stream and an oxidant and output power and substantially purecarbon dioxide; a syngas production unit configured to receive afeedstock and provide a syngas product, at least a portion of which iseffective for use as at least a portion of the fuel stream in the powerproduction unit; an air separation unit configured to provide oxygen foruse as the oxidant in the power production unit and configured toprovide nitrogen; and one or both of an ammonia synthesis unit and aurea synthesis unit.
 24. The system of claim 23, wherein the ammoniasynthesis unit is present and is configured to receive nitrogen from theair separation unit, configured to receive hydrogen from a hydrogensource, and configured to output ammonia.
 25. The system of claim 24,wherein the hydrogen source is a hydrogen separation unit configured toreceive at least a portion of the syngas product from the syngasproduction unit and provide a stream of hydrogen and a stream ofhydrogen-reduced syngas that is effective for use as at least a portionof the fuel stream in the power production unit.
 26. The system of claim23, wherein the urea synthesis unit is present and is configured toreceive nitrogen from a nitrogen source, configured to receive carbondioxide from the power production cycle, and configured to output a ureastream.
 27. The system of claim 26, wherein the nitrogen source is theammonia synthesis unit.